Greetings, and welcome to the Kimbell Royalty Partners Fourth Quarter Earnings Conference Call. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Rick Black from Investor Relations. Thank you. Rick, you may begin.

Thank you, operator, and good morning, everyone. Welcome to the Kimbell Royalty Partners conference call to review financial and operational results for the fourth quarter of 2020. This call is also being webcast and can be accessed through the audio link on the Events and Presentations page of the IR section of kimbellrp.com. Information recorded on this call speaks only as of today, February 25, 2021, so please be advised that any time-sensitive information may no longer be accurate as of the date of any replay. I would also like to remind you that the statements made in today’s discussion that are not historical facts, including statements of expectations or future events or future financial performance, are forward-looking statements made pursuant to the safe harbor provision of the Private Securities Litigation Reform Act of 1995. We will be making forward-looking statements as part of today’s call, which by their nature, are uncertain and outside of the company’s control. Actual results may differ materially. Please refer to today’s press release for our disclosures on forward-looking statements. These factors and other risks and uncertainties are described in detail in the company’s filings with the Securities and Exchange Commission. Management will also refer to non-GAAP measures, including adjusted EBITDA and cash available for distribution. Reconciliations to the nearest GAAP measures can be found at the end of today’s earnings press release. Kimbell assumes no obligation to publicly update or revise any forward-looking statements. I would now like to turn the call over to Bob Ravnaas, Kimbell Royalty Partners’ Chairman and Chief Executive Officer. Bob?

Thank you, Rick, and good afternoon, everyone. We appreciate you joining us for this call. I’m joined here on the call with several members of our senior management team, including Davis Ravnaas, our President and Chief Financial Officer; Matt Daly, our Chief Operating Officer; and Blayne Rhynsburger, our Controller. Before we begin today, I would like to take a moment to extend our thoughts and sympathies to our broad Texas community coming off an extremely difficult experience due to last week’s unprecedented winter storm. While we have never seen such a dramatic event impacting the entire state at one time, contributing to power outages and severe water issues, I continue to be incredibly impressed and humbled by the resiliency of Texans helping one another in difficult times. Now let’s take a look at our company’s performance in the fourth quarter before I hand the call over to Davis to walk you through the financials in more detail. We had a very productive year despite the pandemic and energy sector challenges in 2020. I’m very pleased with our strong operational execution. Our hedge book protected us very well during the year and we continued to distribute tax-efficient cash to unitholders each quarter. We also paid down over $21 million in debt, which strengthened the balance sheet and provided increased flexibility for future acquisitions. We successfully completed a major acquisition of the Springbok assets in 2020, growing total production by approximately 16% in 2020 versus 2019. Also in 2020, we replaced 104% of our PDP reserves and lowered our cash G&A per Boe by 5% in 2020 relative to 2019. In addition, we completed an oversubscribed equity offering, increased our float and trading volume and redeemed 50% of our outstanding preferred units. And finally, we successfully amended and extended our credit facility maturity through 2024, which was significantly oversubscribed and resulted in an 18% increase in aggregate commitments. In the fourth quarter, we began to see a strong recovery in drilling activity on our acreage, with a 30% increase in our rig count, coupled with good sequential improvements in commodity prices and revenue. We are optimistic about 2021 and the continuation of improvements in drilling activity, which is demonstrated by a 14% increase in the Baker Hughes Lower 48 rig count in February 2021 relative to year-end 2020. We are monitoring closely the recent executive orders by the new administration as they relate to new permitting and leasing on federal acreage. We do not believe that these recent executive actions will have a material impact on our existing and future production, and in fact, will have the unintended consequences of driving oil and natural gas prices higher as well as increasing our country’s reliance on imported oil. Heading into 2021, we remain focused on our role as a major consolidator in the highly fragmented U.S. oil and gas royalty sector, assembling a high-quality, low PDP decline and diversified royalty portfolio, generating recurring cash flow with significant growth potential and no capital requirements. We created this company with a long-term vision for sustainability and growth. We believe KRP will continue to be a major consolidator of minerals and royalties across all of the major U.S. basins for years to come. We are very pleased with the continued improvement in commodity prices as we head into 2021, as reflected in the futures curve. During 2020, oil prices averaged $39.34. Looking at the futures curve for the remainder of 2021, oil prices are expected to average $59.34, a 51% improvement relative to 2020. Looking at natural gas, the price improvement is nearly as dramatic. And with approximately 59% of our daily production from natural gas on a 6:1 basis, the price improvement could have a very meaningful and positive impact on our projected cash flows and quarterly distributions during 2021. Natural gas prices averaged $2.13 per Mcf in 2020. The current 2021 strip is indicating natural gas prices will average $2.98 in 2021, which is a 40% improvement over 2020 prices. Our business model is designed to generate positive operating leverage under these types of conditions, since revenues increase, yet expenses remain relatively flat. The result is a direct positive impact on cash flow and distributions per unit. As we broadly look at 2021, we believe the year will be characterized by operators increasing activity, yet maintaining discipline as it pertains to production growth. We believe most operators will either seek to keep production flat relative to 2020 or potentially increase production by low-single digits. Our production guidance for 2021 reflects this belief, with the midpoint of our guidance indicating roughly flat production in 2021 relative to our Q4 2020 average daily production rate. Again, let me summarize by saying that we are very grateful to our employees and advisors for their hard work during 2020, and are very optimistic for 2021 and beyond. We believe that we passed the ultimate stress test during 2020, and look forward to growing our business and driving increased value for our unitholders in the years to come. And with that, I’ll now turn the call over to Davis.

Thanks, Bob, and good morning, everyone. As Bob mentioned, we had a very productive 2020 on a number of fronts. The company paid down $21 million of debt in 2020, and we plan to continue to allocate 25% of cash available for distribution to pay down a portion of our credit facility each quarter. We also locked in interest rates on our revolving debt at a very attractive 3.9% on 87% of our outstanding balances with a three-year interest rate swap, and we amended and extended our revolving credit facility with 18% higher aggregate commitments at an oversubscribed syndication with Citibank as our leader. Just to put this cost of capital into perspective, a number of recent debt issuances in the high-yield market by several small to mid-cap operators had average debt costs of over 8%. We were able to lock in debt costs of 3.9% on 87% of our debt, a 51% lower cost of capital relative to these operators, many of which are much larger than us. This is a testament to the bank group’s confidence in the oil and gas royalty model, which proved itself in a resounding way during 2020 relative to the traditional E&P model. Kimbell will continue to manage and systematically maintain a hedge book that extends forward two years into the future. This systematic hedging strategy proved itself during 2020 as we had substantial hedges already in place before the pandemic occurred, generating millions in realized settlement gains during the worst part of the pandemic. During the fourth quarter, the remaining curtailments that were still in place in the Bakken during Q3 2020 reversed, and we are no longer aware of any ongoing curtailments across our properties. We also continue to maintain a solid inventory of permits and drilled but uncompleted wells across our acreage and expect improvement in these metrics as we progress through 2021 due to the higher rig count. The company’s fourth quarter average daily production was 14,062 Boe per day, comprised of approximately 59% from natural gas on a 6:1 basis and 41% from liquids or 27% from oil and 14% from NGLs. As of December 31, Kimbell had 697 gross and 2.38 net drilled but uncompleted wells as well as 594 gross and 1.94 net permits on its acreage. This data does not include our minor properties, which we estimate could add an additional 20% to the DUC and permit inventory based on our experience. As of the end of December, the company’s rigs increased from 30 at the end of the third quarter to 39 active rigs on our properties or 30%, which represented an approximate 12% market share of all rigs drilling in the Lower 48 at that time. For the fourth quarter of 2020, the company’s oil, natural gas and natural gas liquids revenues were $25.9 million, which reflected Q4 average realized prices of $39.72 per barrel of oil, $2.04 per Mcf of natural gas and $14.98 per barrel of NGLs for a total combined Boe realization of $20.02. On the expense side, general and administrative expenses were $6.4 million at Q4 2020, $4.2 million of which was cash G&A expense or $3.26 per Boe. Q4 2020 consolidated adjusted EBITDA was $17.9 million, up approximately 4% sequentially from Q3 2020. Net loss for the fourth quarter was $93.8 million, and the net loss attributable to common units was $62.2 million or $1.66 per common unit. The net loss for Q4 reflected a $92.9 million noncash ceiling test impairment expense recorded during the quarter related to the substantial weakness in commodity prices. This noncash ceiling test impairment is not expected to impact the cash flow available for distribution generated by Kimbell, nor its liquidity nor ability to make acquisitions in the future. The Q4 2020 distribution of $0.19 per common unit reflects a 75% payout of the Q4 2020 cash available for distribution. We will use the retained amount to pay down a portion of the outstanding borrowings under Kimbell’s credit facility. We continue to manage the company in a disciplined manner, especially given the 2020 macroeconomic turbulence in the energy sector and the broader markets. You will find a reconciliation of both consolidated adjusted EBITDA and cash available for distribution at the end of our news release. Looking now at the balance sheet and liquidity, at December 31, 2020, Kimbell had approximately $171.6 million in debt outstanding under its revolving credit facility and $93.4 million in undrawn capacity. Net debt to Q4 2020 trailing 12-month consolidated adjusted EBITDA was approximately 2.3x. In late January 2021, we entered into an interest rate swap, which fixed the interest rate on $150 million of notional or approximately 87% of Kimbell’s outstanding balance on its credit facility at a very attractive 3.9% for three years. Today, we are providing full year 2021 guidance, which includes production guidance that at its midpoint reflects roughly flat daily production relative to our fourth quarter 2020 daily production. We believe that most operators will focus their 2021 budgets on arresting declines, with a goal of flat to low single-digit production growth in 2021. We believe that Kimbell continues to offer a compelling investment opportunity with growth opportunities and a robust distribution yield, which we expect our distributions to be substantially tax-free through 2023 and instead to be considered a return of capital to the extent of a unitholder's basis in its common units. Kimbell will continue with our goal and focus of generating long-term value and cash generation for many years to come. With that, operator, we are now ready for questions.

Our first question is from John Freeman with Raymond James. Please go ahead with your question.

Good morning, guys. I was trying to get a sense and I don’t know if you all have this handy or not. But when we look at the big increase in the rig count on your properties over the last three months, have you all been able to get any sort of data, just from a high level perspective on maybe what the frac count has done on your acreage over that time frame? Is that something that you all track?

Not traditionally. Matt, I’m trying to think of ways we could help John out with that. Could we look at the quarter-over-quarter change in DUCs maybe? Would that be directionally helpful, Matt? What do you think?

Yes, that’s right. The frac crew quantification that we’ve seen in some of these press releases is extremely hard to pin down. So especially since we’re so diversified. So the best way to look at that, really, is just the change in the rig count, change in the DUCs, change in the permits quarter-over-quarter for sort of the momentum and trajectory for the future.

But I see what you’re getting at, John.

Yes. I think my sense was just that this is such an unusual time period where these companies generally exited 2020 at pretty elevated DUC levels. And so the rig counts, it’s kind of like the frac crews are playing catch-up with the rigs. And so you get a big DUC drawdown that’s, I would assume, a little bit more difficult for you all to kind of handicap than it’s been historically. So that’s all I was trying to kind of get at. But I understand that it was kind of out of left field. So I wasn’t sure if you all had that or not. The other thing that I was curious about, obviously, you all have mentioned a few times in the past that the federal acreage exposure you all have is obviously quite small. And I guess I’m curious on a couple of things. A, would be, have you all seen a material difference yet in the pricing on federal acreage when those opportunities have arisen? And even though historically, you all kind of shied away from the federal acreage, does it get to a point where maybe the pricing gets attractive enough that you all would say, look, this is worth stepping into?

Yes, John, great question. And Bob, I’m going to turn this over to you in a second. I think historically, we’ve always been very wary of federal acreage for very good reasons, and we’re seeing that now. That being said, to your point, John, is there a price at which we would transact? Yes. I mean, I think anything is possible if it makes commercial sense. If we can get a reasonable return based on existing drilled wells, so PDP only, and then have that free optionality for the upside? Yes, I think that’s something that we would consider. Bob, what do you think?

Yes, John, it’s a good question. As you would probably think, in the third and fourth quarters of last year, we saw an influx of calls for people wanting to sell their overrides on federal acreage, especially in New Mexico. And we were just very wary of that. And we didn’t really get to the point of discussion with those sellers of what price they would take. We just told them exactly what Davis said; if you’re willing to sell a PDP, then we will continue discussion with you, and that never really led to anything. But we did see a lot of incoming phone calls for potential sellers in New Mexico, particularly.

John, I’ll answer it in a different way, which is to say the opportunity set on fee minerals on private lands is so robust right now with – I mean, there’s literally no capital in this space, and you’re seeing it, not just in the operating side, but minerals. I mean, there was a couple of billion dollars in capital sloshing around from private equity funds two or three years ago. That is gone. That no longer exists. So I would be more inclined to focus our efforts on federal land if we didn’t have an opportunity set on the private side. But that’s not the case. We’re seeing a tremendous pickup in activity on private land, and that’s where we continue to focus the supermajority of our efforts, if not all of it.

That’s great. And if I just snuck one more in, on the hedging front, you mentioned you’re kind of still sticking with hedging a couple of years forward. Does that – there are some companies where the hedging and the balance sheet are kind of hand-in-hand, and I’m curious if over time, like, let’s say, your leverage got to 1x or better. Does the hedging strategy change at all? Or do you feel like it’s – you’re indifferent relative to the balance sheet and your hedging strategy? Do you view them separately?

No, hand-in-hand. Great question. We will adjust downward the percentage of production that we hedge going forward as we continue to de-lever the business. That’s a great question. So even if we get down to 0.5x levered, we’ll still have some modest amount of production hedged overall. And all we do is we take our debt and divide it by our enterprise value, and that’s the percentage of the production that we hedge going forward. So we’ll keep that formula consistent. The goal is to get leverage so low that the percentage of our portfolio that we have hedged is de minimis. Now that being said, if we see some sort of crazy super spike here with oil prices going up to $100 or $150, god forbid, over the next couple of years; would we consider locking in hedges opportunistically and breaking kind of that consistent rule? I think we would consider it. I think we’d think long and hard about it. But I think overall, every time somebody tries to cherry pick, when they put hedges on or when they roll hedges off, that’s a dangerous gamble to make. And so we like to be consistent quarter-to-quarter on what we do. Anything you’d add to that, Matt?

No, that’s right. I mean we’re roughly about in the high 30s right now on our production hedge for the next couple of years. But as we roll into the hedges in Q1 2023, just with our equity value going up and enterprise value going up and debt going down, sort of it will target more like the high 20s. So it is systematically going to go down over time as we pay down debt.

Very helpful. Appreciate it, guys. Thanks a lot.

Thanks, John.

Yes, thanks, John.

Our next question is from Chris Baker at Credit Suisse. Please proceed with your question.

Good morning, guys. I was just curious on the – in terms of the guidance, I think quite a few folks have talked about weather-related impacts in 1Q. Does the current guidance contemplate any potential impact in the first quarter, just thinking about the general shape? And then as sort of a follow-up, given the advantaged PDP decline, is it possible that we see KRP’s production outperform the general sort of shape that we expect from the E&P?

Tough questions to answer. I would say on the first, given the diversity of our asset base, we haven’t identified or been made aware of any meaningful concentration vis-a-vis weather-related issues. So what we traditionally see on our portfolio is – in the event that we have some sort of weather event like we had, which was terrible here in Texas, we see operators shift activity and increase rates in other areas. That’s one of the reasons why we love a diversified portfolio. So I guess to answer your question directly, yes, I would say that our guidance would bake into account the weather-related effects that we’ve seen, and we don’t expect that to be meaningful for our portfolio or if it is, we would expect a reversal of that and a catch-up in 2Q, 3Q, 4Q, if that makes sense. And can you repeat your second question, Chris? I apologize.

No, it’s fine. Just on the PDP decline, given that it’s quite a bit lower, I think at 12% versus most of the E&Ps. I was just curious, is it possible that we see KRP’s production outperform that general trend, again, just given that there’s a lower requirement to see growth?

Nothing guaranteed, but logic would stand that what you’re saying is correct. And I’ll add on that. We have a considerable amount of natural gas production. And all of a sudden, gas is very attractive to drill. So yes, if pressed and forced to answer that question, I would say, yes, I would expect that’s the reason we built the portfolio, the way that we did. We should outperform the average E&P at a lower rig, tougher environment like this, and we should slightly underperform when things are going gangbusters. So yes, I would agree with what you said. Bob or Matt, anything you want to add?

Yes, going to say a little more color on the first question. So Chris, as you know, we have a relatively large Haynesville exposure. And that area was largely unaffected by the weather shut-ins. I believe Comstock mentioned they had maybe a day or so of shut-ins due to some frozen roads. But given the fact that we have so much Haynesville exposure, that’s going to mitigate some of the effect on the weather shut-ins. But we did – we are going to have some effect from the Permian and Mid-Con as some Eagle Ford. If you were to try to quantify it, I think that we would say something like maybe one or two days of production in Q1 is related to the weather shut-ins, which is I think much less than some other of our peers out there. And then that is, of course, baked into our guidance that we put out there.

Okay, great. And then just as a follow-up, I was hoping that maybe you could help frame up that organic growth slide in the deck. Just in terms of the underlying pieces and maybe how you saw the Springbok assets perform last year versus the legacy portfolio?

Sure. Actually, Blayne, I might turn that over to you. What activity do we see specifically on Springbok this quarter or over the course of 2020 that’s noteworthy that we want to highlight?

Yes. For Springbok, we saw quite a bit of development earlier on in the year in the Eagle Ford. And then here in the fourth quarter, we did have some significant Haynesville production come on in the fourth quarter, specific to Springbok. But early in the year, it was kind of shifted to more in the Eagle Ford and then some Permian development. But then in Q4, it was mainly focused on the Haynesville production.

Bob, anything you want to add on organic growth and the reserves? And by the way, I mean, thank you for asking that question, Chris. I don’t think we get enough credit for having that organic growth in our reserve base every year. I mean it’s just every single year, year in, year out, our reserves are going up at no cost to us. But Bob, anything you want to add on additional color to that?

Yes. I’d just say we’ve been very happy and pleased with organic growth in the Haynesville and then in the Permian. And I’d say that we did see Eagle Ford rig activity go down and then in the STACK, rig activity go down, but offset by increased activity in the Haynesville and Permian. And that’s why we like the diversified portfolio. So obviously, with the curtailments in the second quarter of last year, that organic growth went down. But since then, it’s been coming back, so we’ve been really pleased with this. And I’m just proud of the fact that I – well, I’m just deliver through the – proud of the fact that I think we’ve delivered on what we said we would for years. We’ve never said that we were going to grow at 20% organically. We always said that we would be low single digit, hopefully, even though two years ago, we grew at 8%. And so we’ve hung right in there. When we say it’s going to be flat to low single-digit decline with the guidance, that’s what we’ve always said. We haven’t had to say, well, we’re going from 20% to flat. And so I’m just proud of the portfolio that we’ve built up and how resilient it is.

Chris, one other thing I’ll throw out there, just while I have the opportunity since you mentioned – since Bob brought up the STACK. Nobody likes the STACK right now, and it’s not sexy. But Devon’s spending money up there, right? So we’re going to see – we expect to see some meaningful impact on increased rig count up there. I think it’s Devon. Matt, am I correct on that? So anyway, they have the JV with Dow. Is that right?

Correct.

Great. Thanks. And if I could just squeeze one more in, any update on your viewpoint on M&A? I think you guys have certainly differentiated in your ability to get some larger scale deals over the line. Just curious where your kind of thought process is at this point in 2021.

Absolutely. Still a lot of private equity-backed companies looking for exits, also a lot of operators looking to carve out overrides. We get phone calls all the time to de-lever. I would say that we’re very careful. Some groups just have unrealistic expectations. I would say, in particular, private equity-backed groups that have big Delaware positions, I think have been a little disappointed by the pace at which those properties have been developed and therefore, have lower cash flow generation than perhaps they had hoped. And so that makes it more difficult for us to do something that’s accretive. That being said, there are other groups that are shifting activity now to the Haynesville and other places. So I would expect just like every other year, Chris, I mean, we haven’t gone here without a meaningful deal, I would expect for us to find at least something in the hundreds of millions of dollars over the course of the year. And that’s just my – I can’t guarantee that, but I think we’ll find something accretive. One thing I’d say about M&A activity, Chris, that I think you’ll like is I think sellers are starting to understand and appreciate that the way that the public companies trade dictates how they can make money. And what I mean by that is they’re coming into our offices, and they’re saying, we’re going to start deploying capital in these different basins. What do we need to do so that we can sell to you in such a way that it’s accretive to you guys? And I think they’re finally coming around to that realization that they need for us to make money in order for them to make money, as opposed to two, three, four years ago, we had clowns coming into our office saying that there should be 100 wells per section in the Delaware Basin and that we should bid everything on just a ridiculous NAV with de minimis cash flow. So I think it’s all trending in a rational direction on the M&A front, and I expect – not only us, but also our other public peers to benefit from that. And then the other thing I’d say is people are getting used to selling for equity. We’re not going to lever up this business. I mean this is the most amount of leverage that we want. We’re paying down leverage every single quarter. And I think that the preponderance of our offers, we’re going to sell to you for stock. And if you don’t want stock, then I’m sorry, you’re going to have to go to somebody else. So I think people are getting more rational with that over time, and I’m encouraged. Bob or Matt, anything you want to add to that?

Yes. I’d just say this doesn’t surprise me too much because we’ve seen this through the cycles from doing this for over 20 years, is that when prices hit very low like last year, we go – obviously, our market is high-quality royalties. That’s the last thing that people want to sell, only when they have to, and they want to hold onto it. And so it doesn’t surprise me that we didn’t announce a large acquisition in the fourth quarter just because people say, let’s hold onto it another quarter or two and see if prices improve a little bit coming out of the pandemic. And so I’m – I agree with Davis. I’m very optimistic about transactions later this year as prices stabilize and have already improved above $60. So I think I’m optimistic about M&A. Matt, do you have anything to add?

No, that’s great.

Our next question is from Aaron Bilkoski with TD Securities. Please proceed with your question.

Good morning, guys. To whatever extent you can, I’d be curious on your thoughts about potential redemption of the remaining convertible preferred units.

Well, Matt, are we ready to kind of just lay that out? I think the plan is to take it out as soon as we reasonably can. It’s an expensive piece of paper. Part of the rationale in diverting 25% of our cash flow to debt paydown was to create enough liquidity within our facilities so that we could take that out at the appropriate time. Aaron, I’d say, on or around the midpoint of this year is probably when we expect to redeem the preferred units, and we would envision doing so with a draw on the revolver. And obviously, that’s not only to the benefit of our shareholders directly, but massively accretive when you’re borrowing at 3% and change and taking out a 7% cash, plus a 6% PIK piece of paper. Apollo has been a tremendous partner. And we’ve gotten to a point where we want to clean up the balance sheet and we have the flexibility now in order to do that. So thank you for asking that question. I think that’s – it’s the appropriate question to ask, and I think this is the appropriate time to answer it directly.

No. Thanks. I appreciate that. Maybe on timing, I’m going to push a little bit more on this. Is it fair to say that, that would happen before they would have board observer rights?

Yes. I think that’s fair to say. And that’s – I’m not going to add any color to that. So that’s fine.

Shifting gears a little bit, if I can squeak in a question on operations. In your release, you talked about Permian rig counts in Q4 being up about 30% from Q3 on your lands. If I look at the Baker Hughes rig count, it looks like current activity is up about 30% from Q4. First question is, I guess, are you seeing a similar trend on the lands that you have an interest in? And the second question is roughly what level of activity underpins your 2021 guidance?

Aaron, all great questions, man. We do not check rig count on a day-to-day basis because we have better things to do with our time. Just given how broad our portfolio is, it takes our team a long time to count the number of rigs we have. So we choose it at one point every quarter, and we give that data point out. I mean, Matt, is there anything we can share with Aaron? I don’t think we’ve seen it – I don’t think we’ve done the work to quantify rig activity up and beyond what we’ve just reported. Do you agree with that?

Yes. I mean, Aaron, we generally have about an 11% to 12% market share of the Lower 48 rig count. The rig count was 332 at year-end on the Baker Hughes Lower 48 count. It’s 380, I think the latest count I saw, so assuming we keep that relatively same market share, that would imply that the rig count should continue to go up as we go through Q1.

The other factor – good, great questions. The other factor that we look at is, last year, because of the pandemic, completed wells, the net well count that came online was down slightly, I think, below three net wells for the year, but we still were able to hold production fairly flat. For this next year, we would anticipate, just looking at our DUCs and permits and sort of the pace of drilling, and to your point, increased rig count in the Permian and in other areas around the country, we would hope to see activity levels of converting four-plus wells, net wells. And that’s approximately what we need to maintain production and grow flat. And so that’s kind of embedded in our guidance.

Aaron, I’ll add something else too. Over the next few months, we’re going to start rolling out additional disclosure on our acreage. We’ve kind of alluded to this in the past on previous calls. But there’s more to come on our acreage. And I just hope that you and some of the other analysts and investors pay attention to the additional disclosures that we’re going to roll out. I think it will be helpful to enhance transparency on where our upside is. And the upside is significant. It’s very significant with a low PDP decline. So I just hope that people will pay attention to that, and we’ve deliberately built the business in that way, and I hope that our shareholders get rewarded for it.

Thank you very much, gentlemen.

Our next question is from Derrick Whitfield with Stifel. Please proceed with your question.

Good morning, all.

How are you doing?

Good, good. So to clarify on your 2021 guidance, is it fair to assume that, that was based on Q4 activity metrics?

Matt, how do we want to answer that?

Yes. I would say it’s based on Q4 activity metrics in terms of the rig count, but also the net DUC and net permit count that we had disclosed in our press release at 4.3 combined. So as Bob said earlier, that sort of 4-ish number net wells is what we need to keep production roughly flat for the year. So if you see that net DUC and net permit number trend up during the year, that could certainly imply that the production could skew towards a little bit above the midpoint level. But overall, as you’ve seen from these conference calls, and I’ve listened to about 20 of them from these operators, everybody is sort of working towards flattish production in 2021 with maybe low single-digit growth. So there’s no reason why given our portfolio that we should try to obtain something higher than flattish, maybe slight growth, if that makes sense.

Yes. Derrick, I’ll repeat what Matt said. It’s mostly driven by DUC and permit activity. And then rig count would be kind of a secondary, but dramatically less important indication of what our guidance is based on. We’re looking for immediate catalysts to arrest the decline. And as Bob and Matt have identified a number of times on this call, that’s the DUC and permit inventory, and that’s kind of around that four number on the net wells.

That’s great. I mean it sounds conservative, and that’s the right way to approach it. So on my follow-up question, maybe shifting back over to the M&A topic. Could you update us on the progress of your micro strategy, the ground game strategy, if you will?

Yes. The results have been fantastic in terms of the results that the Springbok guys, Ryan Watts and his team are incredible in what they do. And we’re very fortunate to be partners with them. But the pace of deploying capital has been slower than I think we all collectively expected. And that’s mostly just been because of everything that’s happened last year. So Matt, you have the numbers. I think it’s what, $2 million that we’ve deployed that we deployed over the course of the last year? Maybe just update everybody on what…

Yes, the last year, that’s correct. But yes, since inception, since inception of doing this, we’ve deployed $5.2 million in the strategy. We’ve closed 28 transactions. The average size is around $300,000 per transaction, deals in the Delaware Basin, Haynesville, Bakken. We made a $0.5 million investment, relatively small in Q4, had the next 12-month unlevered projected yield in the low 20s. So they’re doing extremely well.

Yeah, unlevered.

Great. Thanks for the detail and your time.

You too, Derrick.

And there are no further questions at this time. I would like to turn the floor back over to management for closing comments.

We thank you all for joining us this morning and look forward to speaking with you again when we report first quarter results. This completes today’s call. Thank you very much.

Ladies and gentlemen, thank you for your participation. This does conclude today’s teleconference. You may disconnect your lines, and have a wonderful day.